Top mount dual bit well drilling system

ABSTRACT

A top mount dual bit well drilling mechanism has a rotary driven tubular housing having a top mount body within an upper end portion of the housing to which the upper end of a mud motor is mounted for support within the housing. A reamer bit is connected for rotation by the tubular housing upon rotation by a well drilling string and defines a core removing bit chamber that is recessed within the reamer bit and has communication with the core receiving receptacle. A core removing bit is rotated within the core removal bit chamber by the mud motor and continuously cuts away the upper end of a formation core that enters the receptacle as the reamer bit cuts into the formation.

RELATED PROVISIONAL APPLICATION

Applicant hereby claims the benefit of U.S. Provisional PatentApplication No. 61/886,498, filed on 3 Oct. 2013 by Edwin J. Broussard,Jr. and entitled “Steerable Well Drilling System”, which provisionalapplication is incorporated herein by reference for all purposes.

RELATED UTILITY APPLICATION

This application is related to the subject matter of pendingnon-provisional application Ser. No. 14/085,091, filed on Nov. 20, 2013by Edwin J. Broussard, Jr. and entitled “Steerable Well DrillingSystem”.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates generally to well drilling systems andparticularly to well drilling mechanisms having a reamer bit defining acentral opening within which a formation core is permitted to enter asthe reamer bit progresses into the formation. The well drilling systemof the present invention has a core removal bit that is located withinthe reamer bit and is independently rotated for continuously cuttingaway the core of formation material that is not cut away by the rotatingcutters of the reamer bit.

The present invention also concerns dual drill bit well drilling systemshaving a drilling housing to which is mounted a reamer bit. The housingand the reamer bit are rotated by any suitable rotary power system suchas a rotary drill string or a drilling fluid driven rotary motor, alsoknown as a “mud motor”. Within the drilling housing is mounted a coreremoval bit mud motor that has drilling fluid energized driving relationwith the core removal bit and accomplish continuous cutting of the upperend portion of the remaining formation core. The core removal bit ispreferably composed of a metal bit body structure, typically composed ofsteel, to which is adhered a carbide or other hard-facing material thatdefines cutter elements and having a PDC coating to enhance thedurability thereof. If desired, the core removal bit may have amultiplicity of PDC cutter elements affixed thereto or may have anyother drill bit form that is suitable for cutting away the remainingformation core that is left by the reamer bit, without departing fromthe spirit and scope of the present invention. Generally, the terms“cutting elements” or “cutting face”, as employed in this specification,means a range of formation cutting devices including PDC cuttingelements, carbide cutting elements, PDC coated carbide or metal bitstructure, bits defining hardened metal cutting teeth, and the like asis deemed suitable for efficient cutting of the character of formationmaterial that is being drilled.

The reamer bit preferably incorporates polycrystalline diamond (PDC)formation cutting elements that are supported by a matrix material thatis affixed to a reamer bit body but may also incorporate hardened metalcutting elements or rotary cone cutting elements, if desired. Evenfurther, the present invention concerns a dual bit wellbore drillingsystem having a reamer bit that has no central cutting elements andtherefore leaves a central core of formation material during drilling.The reamer bit therefore defines a downwardly facing central openingthat is entered by the central core as the reamer bit progresses intothe formation during drilling activity. The smaller, mud motor drivencore removal bit is either located concentrically or eccentrically withrespect to the reamer bit for efficiently removing the remaining corematerial from the top of the core simultaneously with formation cuttingby the reamer bit.

2. Description of the Prior Art

Dual PDC well drilling systems having an external reamer bit and aninterior mud motor driven core removal bit are disclosed by U.S. Pat.No. 7,562,725 of Edwin J. Broussard, Jr. and Herman J. Schellstede. Areamer bit is mounted to and rotated by a rotary drill string thatextends from a rotary drilling rig at the surface. The core removal bitis rotated by a mud motor that is located within a drilling unit, themud motor being driven by the flow of drilling fluid that is pumpedthrough the drill string from the surface. Another somewhat similardrilling system is disclosed by U.S. Pat. No. 8,201,642 of Steven J.Radford, et al, wherein a reamer bit is rotated in one direction by thedrill string and a concentric bit is located within the reamer bit andis rotated in a counter rotational direction by a downhole motor such asa positive displacement motor (PDM). It is noted that the smallercentrally located bit is located entirely within the outer reamer bit,with its cutting elements engaging the central portion of the formationwithin which the wellbore is being drilled. The drill cuttings of thesmaller bit will tend to build up on the cutting interface of thesmaller bit, thus further interfering with its formation cuttingcapability. Though these types of drilling systems will function andachieve wellbore drilling, typically no provision is made forcontrolling the delivery of drilling fluid for reamer drilling, coreremoval bit drilling, mud motor operation and bearing cooling for themud motor and other components of the drilling system.

During well drilling with a conventional PDC bit, it is known that themost central of the PDC cutter members will be rotated against theformation being drilled at a slower speed as compared with the PDCcutter members that are located further from the center portion of thebit. This difference in formation cutting speed is due to thecircumferential distance each of the PDC cutter members travel duringeach revolution of drill bit rotation. The cutter members at the outerperiphery of a drill bit travel at a greater formation cutting speedthan the cutters near the center of the bit. The slower cutting speed ofthe more centrally located cutters causes inefficient formation cuttingat the central portion of the borehole being drilled, so that thecentral portion of the drill bit cutting face tends to crush, ratherthan cut the formation material, and thus retards the overallpenetration rate of the bit. It is considered desirable therefore, toemploy the benefits of PDC cutter members for rotary well drillingwithout having the well drilling efficiency hampered by inefficientformation cutting at the central portion of a drill bit.

It has been determined that by relieving the central portion of thecutting face of a drill bit, the formation cutting efficiency andpenetration rate of the bit will be significantly enhanced. However,such a drill bit will permit a central formation core to remain. Thiscore must be removed so that it will not interfere with the drillingprocess. According to U.S. Pat. No. 7,562,725 of Edwin J. Broussard andHerman J. Schellstede, a dual PDC drilling system is provided having anouter reamer bit for cutting away a major part of the formation duringdrilling and having an inner core removal bit that is independentlyrotated, such as by means of a mud motor or other rotary power system ofthe drilling mechanism and which functions to continuously andcompletely cut away the remaining central formation core that is not cutaway by the reamer bit. U.S. Pat. No. 8,201,642 discloses a dual bitwell drilling system having a reamer bit and a small centrally locatedbit within the reamer bit that is rotated in a direction that isopposite the rotation of the reamer bit. Another well drilling systemhas been developed which employs a rotary PDC reamer bit for primarydrilling and employs a fixed PDC element at the center of the reamer bitto fracture away or crush the formation core material that is not cutaway by the reamer bit.

PDC drill bits typically drill an oversize wellbore, and thus allow forlateral movement of the drill bit within the formation while drilling.This lateral drill bit movement is undesirable because it causes theresulting borehole to be oversize or out of gauge and will often causethe PDC cutters to be sheared from the bit. Drill bit manufacturersrecognize this potential problem and are known to design the PDC bits tohave a somewhat concave cutting face and rounded towards the outerperiphery. This bit geometry causes wedging of the drill bit into theborehole and thus minimizes the potential for lateral bit movementduring drilling and also minimizes the development of shearing forces onthe PDC cutter members. However, these concave PDC bit designs cause thecutter area of the bits to be increased and thus cause the cost of theresulting bit to also be increased. This increased drill bit cost is acommercial disadvantage in the well drilling industry.

The dual PDC drill bit arrangement of the present invention achievesmore rapid penetration in most hard subsurface formations becausedrilling penetration is not resisted by poor drilling capability of thecentral portion of the bit and by the presence of a formation core thatdevelops between the PDC bit blades and retards penetration movement ofthe bit. The larger the core diameter is and longer it is, (to a point)will significantly stabilize the bit during its drilling rotation andthus minimize the lateral movement that is typically inherent in causingthe drilling of oversize wellbores by PDC drill bits. The faster therate of penetration, the more properly gauged the resulting wellborewill be and the better the bit will be stabilized during its rotationaloperation. With these advantageous features of bit design incorporated,a flatter PDC bit could be built, having less surface cutter area,thereby minimizing the number of PDC cutters that are employed in bitdesigns and minimizing the application of torque force to the drillstring.

SUMMARY OF THE INVENTION

It is a principal feature of the present invention to provide a novelwell drilling system that is adapted for threaded mounting to a bit boxof a drill string or mud motor for straight drilling.

It is also another feature of the present invention to provide a novelwell drilling system that may incorporate any of a number of differenttypes of formation cutting elements, such as polycrystalline diamondcutting elements, hardened metal cutting elements, rotary cone type rockbits within the spirit and scope of the present invention.

It is also a feature of the present invention to provide a novel welldrilling system having a reamer bit that is rotationally driven by adrill string or by any other rotary drive mechanism and a core removalbit that is located within a tubular housing of the well drilling systemand is rotated along or near the longitudinal axis of the reamer bit.

It is another feature of the present invention to provide a novel welldrilling system having fluid flow control features to ensure optimumdrilling by a reamer bit and a core removal bit and to further ensureoptimum flow of drilling fluid for cooling of mud motor bearings and formud motor operation.

It is an even further feature of the present invention to provide anovel well drilling mechanism having a PDC reamer bit that is capable ofbeing rotationally driven by a rotary drill string or a mud motor thatis mounted to a rotatable or non-rotary drill string and which defines acentral bit opening within which is located a formation core removingrotary bit that is independently driven in the direction of rotation ofthe reamer bit or in the opposite direction of rotation of the reamerbit.

It is also a feature of the present invention to provide a novel welldrilling mechanism having a core removal mud motor and core removal bitassembly that is supported in eccentric or concentric relation within adrill housing by a top mount section of the tubular drill housing andpositions a core removal bit for mud motor driven rotation within a bitchamber for continuous cutting of a formation core that remains asreamer bit drilling occurs.

Briefly, the various objects and features of the present invention arerealized through the provision of a well drilling system having atubular housing that is connected with a drill string and has coreremoval bit assembly that is supported within the housing by a top mountwithin the upper end portion of the tubular housing of the well drillingsystem. The housing of the top mount well drilling system has aninternal mud motor and may be mounted to the lower end of a drill stringextending from the drilling rig at the surface and only rotates if thedrill string is rotated from above via rotary/kelly or by the top driveof a drilling rig.

The rotation speed of the inner core removal bit is determined accordingto the characteristics of the different types of subsurface formationsthat are encountered. It is expected that the rate of penetration willincrease geometrically since the inner core of the formation iscontinuously and completely cut away from the top down, rather thanbeing chipped or crushed as is typically the case with conventional PDCbits.

The well drilling mechanism has a housing to which is mounted reamer bithaving a small mud motor located within the housing and supported by thetop portion of the housing. This small mud motor is arranged to drive acore removal bit at higher rpm's than that of the reamer bit. The rateof penetration of the well drilling system of the present invention, incomparison with conventional PDC drilling systems, increasesgeometrically. Because the present invention has a combination of a PDCreamer bit with a mud motor driven core removal bit, which has PDCcutters on the reamer bit, whether the core removal bit be centered oroffset from the center-line of the larger reamer bit, achieves efficientremoval the formation core while drilling more efficiently with thereamer bit.

The dual bit drilling mechanism of the present invention has an outerreamer bit that has been bored or otherwise prepared for containing asmall mud motor having a bearing pack that is provided for wearresisting rotary support of a drill bit drive shaft. A core removal bitis threaded to the drive shaft mechanism of the small mud motor and ispositioned within a bit chamber that is defined within a reamer bitbody. When the drilling system is designed for left hand rotation of thereamer bit, opposite the typical direction of rotation of the reamer bitby a well drilling system, the various threaded connections of the mudmotor bearing pack components will have left hand threads to resist theleft hand reactive torque that is received due to cutting engagement ofthe core removal bit with the remaining formation core. When the mudmotor imparts left hand rotation to the core removal bit, left handreactive torque of the mud motor will be applied to all connectionsexcept the connection of the core removal bit to the bit drive shaft.

Only a small amount of power is required to rotate a relatively smallbit, such as 1¼″ core removal bit. Also the mud motor has a smallerbearing pack with a larger power section driving the core removal bit toensure adequate rotational power. The PDC reamer bit has fluid passagesthat are nozzled to a specific size, creating internal bit pressure thatforces drilling fluid through the mud motor power section, rotating thecore removal bit below. This feature allows the bearing pack fluid todivert to the lower pressure of the well bore annulus, therebysimultaneously cooling the mud motor bearing pack and the core removalbit, and flushing away drill cuttings from the core removal bit. Theentire drilling assembly can be threaded into the bit box of a bottomhole assembly for straight wellbore drilling.

The dual drill bit mechanism of the present invention has a combinationof a PDC reamer with a mud motor driven core removal bit, with PDCcutter elements mounted to the reamer bit by means of cutter retentionmatrix or by any other suitable means for cutter retention. Whether thecore removal bit be centered or in laterally offset relation with thelarger reamer, the core removal bit cuts away the formation core moreefficiently while drilling. The optimal offset distance of the coreremoval bit relative to the center or axis of reamer bit rotation willbe determined by the well drilling parameters at any point in time.

The PDC reamer bit has fluid passages that are nozzled to a specificsize, creating predetermined internal bit pressure, thereby forcingdrilling fluid through the mud motor power section, rotating the coreremoval bit below. The mud motor is supported within the tubular housingof the drilling system by a top mount body or housing section which alsoserves to isolate the bearing pack fluid bypass opening from the highpressure chamber that is within the housing of the drilling system. Thisfeature allows the flow of bearing pack fluid to be diverted to thelower pressure of the well bore annulus, thereby simultaneously coolingthe mud motor bearing pack and the core removal bit and serving to flushdrill cuttings from the core removal bit. A hardened internal wearresisting sleeve is located within the reamer bit to prevent wear to thereamer bit by the core removal bit. The complete drilling assembly isadapted to be threaded into the bit box of the drill string for typicalstraight hole drilling.

The PDC cutters near the center of the reamer bit can be designed toslightly overlap the reamer core area, cutting the edge of the core andpreventing core contact with the reamer bit. However, it should be bornein mind that the presence of a small formation core can have astabilizing effect on the PDC reamer bit, by serving to ensure againstlateral deviation of the reamer bit from a straight course. Also becauseof wellbore core removal, minimal bottom hole assembly weight isrequired to cause the PDC cutters to efficiently penetrate into theformation and drill a straight hole effortlessly. As more weight addedto any drill bit, it will force the drill collars above to flex and layto one side of the well bore, causing the drill bit to be cocked on aslight angle, thereby drilling off in a selected direction. Thus, thedrilling system is capable of directional drilling for correction ofwellbore direction as needed. If drilling continues in the selecteddirection, the angle of the drill bit will continually increase asadditional borehole is drilled. There will also be less heat generatedby friction due to efficient cutting of formation material, rather thanhaving the PDC cutters at the central portion of a standard PDC bitslide on top of the formation or crush the formation rather than cuttingit, thereby extending PDC drill bit life dramatically.

Significant vibration is typically experienced when the rotor of the mudmotor of the core removal bit is spinning within the stator in responseto drilling fluid flow. For this reason, resilient stabilizers formed ofrubber or rubber-like polymer material are provided within the mud motorto absorb the vibration. This feature prevents damage to the small PDCcoated carbide core removal bit as it spins within the core removal bitchamber of the reamer bit. The offset core removal bit will be recessedbehind the PDC cutters of the reamer bit and is positioned for efficientremoval of the formation core that remains as the reamer bit penetratesinto the formation. The optimal recessed distance of the core removalbit is determined by the parameters of the formation being drilled;however, it should be borne in mind that the formation core also servesto stabilize rotation of the reamer bit. With the core removal bitcentered within the reamer bit, it can be recessed behind the PDCcutting members on the blades of the reamer bit and protrude out of thereamer bit, provided the core removal bit outer diameter overlaps thePDC cutters in the center of the reamer bit.

Though the mud motor powered rotary drilling system or head mayincorporate a variety of formation cutting or eroding elements, such aspolycrystalline diamond (PDC) cutting elements and hardened metal rockcutting or chipping elements, steel, carbide or other metal cuttingmembers, which may include hard-facing material or PDC or other hardcoatings, for purposes of simplicity the invention is discussed hereinas it concerns formation boring by using PDC cutting elementsparticularly for the reamer bit. The drilling mechanism has a tubularhousing that is connected with a mounting sub that is connected with adrill string extending from a drilling rig the surface. The lower endportion of the tubular housing is provided with a vibration isolationmember to dampen any vibration forces that are encountered. A reamer bitis connected with the lower end of the tubular housing below astabilizer that ensures centering of the drilling system within thewellbore being drilled.

A mud motor is located within the tubular housing of the well drillingsystem and includes a rotor having an axis of rotation that can beconcentric or eccentric with respect to the longitudinal rotational axisof the tubular housing and reamer. The drilling fluid inlet of the mudmotor is in communication with a high pressure fluid chamber that isdefined within the tubular housing. An interchangeable orifice flowcontrol nozzle is present within the partition for control of drillingfluid flow past the mud motor for cooling and cleaning of the reamer bitand for cooling and lubricating the bearing pack of the mud motor.

The bottom hole drilling mechanism incorporates an external reamer bithaving a central portion with no cutting elements, thus defining adownwardly facing central opening that is entered by a central formationcore as formation drilling progresses. The formation core that remainsas the reamer bit is operated is cut away from top to bottom by a mudmotor driven core removal bit that is located for mud motor poweredrotary movement within a core bit chamber within the reamer bit.Preferably, the core removal bit is a carbide bit having core cuttingedges or teeth and being formed of carbide material that is preferablycoated with PDC material. Alternatively, the core removal bit may have acutting face that is defined by a multiplicity of PDC cutting elementsthat are secured to the bit structure by a cutter retaining matrixmaterial. The core removal bit may have other forms and may be composedof a variety of formation cutting elements or teeth; however each of itsvarious forms and materials permits the core removal bit to cut away theremaining formation core from the top down as penetration of the reamerbit progresses into the formation.

The core removal bit mud motor is mounted within the reamer bit headtypically by being threaded into a threaded receptacle of a top mountsub that is provided within the upper end of a drilling housing. Thecore removal bit is provided with formation cutting elements and isrotated at a different, typically higher rate of rotation as comparedwith the rate of rotation of the reamer bit. However, if the coreremoval bit has the same rotary speed as the reamer bit, the rotaryspeed of the core removal bit will be added to the rotary speed of thereamer bit, causing the core removal bit to rotate at a faster rotaryspeed than the reamer bit. The reamer and core removal bits work inconcert to facilitate a greater overall formation penetration rate ascompared with conventional PDC drill bits.

The fluid flow that operates the mud motor is also employed for coolingand cleaning of the core removal bit. The core removal bit has aplurality of drilling fluid passages that permit the flow of drillingfluid for cleaning of the cutting elements of the core removal bit andfor cooling and lubricating the bearing pack of the core removal bit topromote extended service life thereof. Drilling fluid flow through thereamer passages is selectively adjustable by means of replaceable flowcontrol nozzles that are sized according to well drilling parameters,such as well depth, formation character and hardness, fluid pressure atthe drill bits, and the like.

When the core removal or inner bit is rotated about an axis of rotationthat is offset from the rotational axis of the reamer bit, the coreremoving cutting edges of the core removal bit are not centered on thetop of the formation core, but rather cut across the top surface of thecore to cut it away from the top down. Regardless how big or what theoffset of the core removal bit is, the recessed core removal bit willalways remove the remaining formation core that is not cut away by thePDC cutter elements of the reamer bit. As the formation core iscontinuously cut away by the core removal bit, it does not restrict theefficiency of formation penetration by the PDC cutters of the reamerbit.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features, advantages andobjects of the present invention are attained and can be understood indetail, a more particular description of the invention, brieflysummarized above, may be had by reference to the preferred embodimentthereof which is illustrated in the appended drawings, which drawingsare incorporated as a part hereof.

It is to be noted however, that the appended drawings illustrate only atypical embodiment of this invention and are therefore not to beconsidered limiting of its scope, for the invention may admit to otherequally effective embodiments.

In the Drawings:

FIG. 1 is a schematic illustration showing a well drilling rig that islocated at the surface of the Earth's surface and extends a drill stringor stem into a wellbore that is being drilled and shows a well drillingsystem embodying the principles of the present invention being connectedwith the drill string;

FIG. 2 is a longitudinal sectional view of an upper portion of a duelbit well drilling mechanism embodying the principles of the presentinvention and showing top mounting of an eccentrically arranged drillingfluid energized rotary motor for operation an core removing drill bit ofa dual bit drilling system and showing mounting of the drilling systemto a drill string;

FIG. 3 is a longitudinal sectional view similar to that of FIG. 2showing an intermediate section of the well drilling system of FIG. 2;

FIG. 4 is a longitudinal sectional view similar to that of FIGS. 2 and 3showing a bearing pack section of the well drilling system of FIGS. 2-4;

FIG. 5 is a longitudinal sectional view showing a dual bit well drillingmechanism having an exterior reamer bit and having an eccentricallyarranged internal core removal bit being rotatably driven by thedrilling fluid energized rotary motor;

FIG. 6 is a bottom view of the dual bit well drilling mechanism showingright hand rotation of the exterior reamer bit and left hand rotation ofthe internal laterally offset core removal bit;

FIG. 7 is a longitudinal sectional view showing a laterally offset coreremoval bit having an external reamer bit that is rotated to the rightduring drilling and an internal core removal bit that also rotated tothe right by its drilling fluid energized rotary motor;

FIG. 8 is a bottom view showing the dual bit mechanism of FIG. 7 andillustrating the overlapping relation of inner portions of the PDCcutter supporting blades of the reamer bit with the cutting face of theinternal core removal bit;

FIG. 9 is a longitudinal sectional view, similar to FIG. 2, showing theupper section of a well drilling housing having an eccentricallyarranged drilling fluid energized rotary motor for rotary actuation ofan eccentric or laterally offset core removal bit;

FIG. 10 is a longitudinal sectional view, similar to FIG. 9 showing flowcontrol nozzles being arranged for controlling the flow of drillingfluid through an external annulus, and for controlling the flow ofdrilling fluid through the drilling fluid energized rotary motor;

FIG. 11 is a longitudinal sectional view of a dual bit well drillingsystem having a concentrically arranged drilling fluid energized rotarymotor with drilling fluid flow control by flow passage dimensions;

FIG. 12 is a longitudinal sectional view showing the concentricallyarranged drilling fluid energized rotary motor of FIG. 11 and showingflow control nozzle being mounted for controlling the flow of drillingfluid through the drilling fluid energized rotary motor of the dual bitdrilling system of the present invention;

FIG. 13 is a longitudinal sectional view showing a bearing pack sectionof the dual bit drilling system of FIG. 12;

FIG. 14 is a longitudinal sectional view of the lower section of thedual bit drilling system of FIGS. 11-13 showing the concentric dual bitmechanism, with the reamer bit arranged for right hand rotation and theinternal core removal bit also arranged for right hand rotation;

FIG. 15 is a bottom view of the concentric dual bit mechanism of FIG. 14showing an overlapping relation of the inner portions of the PDC cuttersupporting blades of the reamer bit with the cutting face of theinternal core removal bit;

FIG. 16 is a longitudinal sectional view showing the concentricallyarranged dual bit drilling mechanism with the external reamer bitarranged for right hand rotation during drilling and the internal coreremoval bit being arranged for left hand rotation;

FIG. 17 is a bottom view showing the concentric dual bit well drillingsystem of FIG. 16 and further showing an overlapping relation of theinner portions of the PDC cutter supporting blades of the reamer bitwith the cutting face of the internal core removal bit;

FIG. 18 is a longitudinal sectional view showing the upper portion of aconcentrically arranged drilling fluid energized rotary motor for aconcentric dual bit well drilling mechanism and showing a splinearrangement maintaining a non-rotatable relation of the motor mechanismwithin the tubular housing of the well drilling system;

FIG. 19 is a longitudinal sectional view showing an upper portion of aconcentrically arranged drilling fluid energized rotary motor alsoshowing a spline arrangement maintaining a non-rotatable relation of themotor mechanism within the tubular housing of the well drilling system;

FIG. 20 is a section view taken along line 20-20 of FIG. 19;

FIG. 21 is a longitudinal sectional view showing the dual bit welldrilling system of the present invention with the mud motor and coreremoval bit of the dual bit well drilling mechanism being concentricallyarranged and having gauge control elements being mounted to ensureformation core controlled stability of the reamer bit against undesiredlateral deviation from its intended course during drilling activity;

FIG. 22 is a longitudinal sectional view showing the dual bit welldrilling system of the present invention and showing an eccentricallyarranged drilling fluid actuated rotary motor and an eccentric coreremoval bit positioned within a gauge lined central core receptacle ofthe reamer bit;

FIG. 23 is a transverse section view taken along line 23-23 of FIG. 22and showing flow control nozzles;

DETAILED DESCRIPTION OF PREFERRED EMBODIMENT

While the well drilling system is discussed herein particularly as itconcerns PDC drill bits, it is not intended to limit the spirit andscope of the present invention to such, since this invention isadaptable to a variety of drilling systems, including systems foreffectively drilling materials other than earth formations. Referringnow to the drawings and first to the schematic illustration of FIG. 1, awell drilling rig 10 is shown that is located at the surface “S” of theEarth. The well drilling rig has a rotary turntable 12, rotary top driveor other rotary drive mechanism for rotating a kelly 14 to which isconnected a drill string 16 that is composed of multiple sections ofdrill pipe, also known as drill stem. The drill string 16 extends fromthe drilling rig into a wellbore 18 that is being drilled throughvarious earth formations 20 to one or more production zones that maycontain crude oil, natural gas, distillate and other petroleum products.The drill stem or pipe 16 of the drill string is tubular and defines acentral flow passage 22 through which drilling fluid, also calleddrilling mud, is pumped for the purpose of cooling and lubricating thedrilling mechanism and flushing away drill cuttings and other debristhat is loosened from the formation during drilling. When drilling astraight wellbore, the rotary drive mechanism of a drilling rigcontinually rotates the drill string and drilling fluid is continuouslypumped through the drill pipe while the weight of the drill string isapplied to the drill bit to drill straight ahead. When the well drillingsystem is being used to drill a directional wellbore, as drilling fluidis through the drill pipe and with the drill string stationary, a benthousing mud motor is rotationally oriented to the desired direction forwellbore deviation or correction. The well driller will then slide thedrill string ahead to correct the course of the wellbore or to changethe wellbore direction. After sliding the drill string a desireddistance to achieve the well correction or change that is desired, thedriller will then begin to rotate the drill string and once again anddrill straight ahead.

A well drilling mechanism 26 is connected with the bit box of the mudmotor powered drilling mechanism 24, will be hydraulically powered bypressurized drilling fluid that is pumped through the drill stem to thedrill bit or bits 28 of the well drilling mechanism 26. Every mud motorhas two sets of threads, internal threads and external threads. With astandard mud motor, the internal and external threads constitute righthand threads because the mud motor is supported at its upper end by thedrill string. The left hand reactive torque that occurs during drillingtends to tighten all of the right hand threads of the outer body of themud motor. All internal threads of the motor constitute right handthreads because the motor rotor drives the drill bit to the right andthus has the effect of tightening all of the threads beneath it. Theopposite effect occurs during the practice of the present invention,when the mud motor is arranged to rotate a core removal bit to the left.The mud motor for driving the core removal bit of the present inventionis supported at its upper end by a top mount that is located within atubular drilling body that is in turn supported by a rotary drillstring.

As shown in FIG. 2-5, at the lower or distal end of the drill string 16is mounted a dual bit well drilling mechanism shown generally at 30,which is typically rotated by a drill string, but can be rotated by amud motor if desired. The dual bit well drilling mechanism 30 isemployed to achieve rotation of a reamer bit, shown generally at 32, anda core removal bit, shown generally at 34, both being shown in FIG. 5.The dual bit well drilling mechanism 30 comprises a tubular housing,shown generally at 36 in FIG. 2, which is comprised of a mounting sub 38which defines an upwardly projecting externally threaded connection 40that is received by the internally threaded receptacle 42 of a bit boxconnector 44. The tubular housing 36 of the drilling fluid energizedrotary motor or “mud motor” further includes an upper housing section 46having an upper internally threaded connection 48 having threadedassembly with an upper externally threaded connection 50. The upperhousing section 46 also functions as an outer reamer drive member andhas threaded connection at 49 with a lower housing section 51 which isthreadedly connected at 47 with a reamer bit body 52. The lower housingsection 51 is typically provided with a plurality of external elongateradially spaced centralizer members 53 that centralize the drillingmechanism within a wellbore being drilled. Spaces between thecentralizer members define flow passages within the wellbore andexternally of the tubular housing for the return flow of drilling fluidand drill cuttings after the drilling fluid has been discharged from thedrill bit mechanism of the well drilling system.

The reamer bit body 52 is typically composed of a durable metalcomposition, such as steel, and defines an external surface 54, as shownin FIG. 6, to which a cutter retention matrix 56 is affixed by bonding,welding or by any other suitable means for attachment. As is evidentfrom the bottom view of FIGS. 5 and 6, the cutter retention matrix 56 isformed to define a plurality of outwardly radiating vanes or blades 58,having leading edge portions 60 that define a multiplicity of cutterreceptacles 62 each having a PDC cutter element 64 secured immovablytherein. Thus, a plurality of substantially radially oriented arrays ofPDC cutter elements 64 are arranged to present cutting edges that engageand cut away a small portion of the formation/reamer bit interfaceduring each rotational revolution of the reamer bit. Collectively, theradiating arrays of PDC cutter elements 64 continuously cut away themajor portion of the formation material within which the wellbore isbeing drilled. Gauge or wear pad members 66, which may be defined by PDCmembers or by any other hard and wear resistant material, are retainedby the cutter retention matrix material 56 and serve to minimize thepotential for wear of the cutter retention matrix material as the outerwall of the reamer bit is rotated in contact with the abrasive wallsurface of the wellbore.

When drilling with conventional PDC drill bits the centermost PDC cutterelements tend to crush the central portion of the formation materialwithin the borehole, rather than cut it away, due to the inefficientcutting characteristics of the PDC cutters at the central region of thebit. Even when a PDC bit is provided with a small concentric bit, suchas taught by U.S. Pat. No. 8,201,642, for drilling a central portion ofa borehole, the center portion of the small concentric bit also tends tocrush, rather than cut away the central formation material due to theinefficient formation cutting characteristics of the centrally locatedformation cutting elements of the small concentric bit. However, as isevident from FIGS. 5-8 of the drawings, the reamer body 52 and the innerportions of the cutter support blades 58 define a downwardly facingcentral opening 68 which, since the reamer bit has no central cutterelements to retard drill bit penetration, maximizes formation cuttingefficiency of the reamer bit. The open central portion of the reamer bitpresents virtually no resistance to bit penetration as is typicallyexperienced by conventional PDC drill bits having formation cutterelements at the central portions thereof. However, during drillingactivity a central portion of formation material is not cut away andthus defines a formation core 69 that enters the central opening 68 asthe reamer bit cuts away the formation material. The core removal bit 34is positioned to efficiently cut away this central formation core as thereamer bit continues to cut away the formation material.

The downwardly facing central opening 68 is collectively defined byinner surface sections 71 of the cutter support blade members 58 asshown in FIG. 6. A cylindrical wall surface 76 is defined within thereamer bit body 52 and partially within the matrix material 56 and iseccentric with respect to the center-line C/L¹ of the reamer bit body,such that its center-line C/L² is laterally offset with respect tocenter-line C/L¹. The cylindrical wall surface 76 defines a bit chamber77 within which the core removal bit 34 is positioned for core cuttingrotation. It should be borne in mind, however, that the core removal bit34 can be either eccentrically located or concentrically located withrespect to the center-line C/L¹ of the tubular housing 36.

As shown in FIGS. 2-10, the core removal bit 34 is positioned within acore bit chamber 77 for rotation about the center-line C/L² and has acore cutting face 70 that is recessed inwardly of the central opening 68for cutting engagement with the upper end of the formation core, that isshown in broken lines at 72 in FIG. 5, and remains as the reamer bitprogresses into the formation during drilling. The outer, generallycylindrical surface of the core removal bit 34 is spaced from theinternal cylindrical wall 76 so as to define an annular clearance 75through which drilling fluid is permitted to flow for cooling andcleaning the core removal bit. The core cutting face 70 of the coreremoval bit 34 is provided with a plurality of cutting elements 73 thatserve to continuously and completely cut away the remaining formationcore that is not cut away by the cutting elements 64 of the reamer bit32. Preferably, however, the core removal bit 34 and its formationcutting elements are composed of a hardened and durable metalcomposition such as tungsten carbide that may be coated with PDCmaterial to enhance the durability of the cutting face. It should benoted that the reamer bit 32 is typically rotated by a rotating drillstring or may be rotated by a drilling fluid energized mud motor that isconnected with a drill string. However, the core removal bit 34 isindependently rotated by a drilling fluid energized rotary motor or mudmotor shown generally at 74 which is located within the tubular housing36 of the well drilling mechanism 30. The generally cylindrical bore orwall 76 is formed eccentrically with respect to the center-line of thetubular housing 36 and defines a bit chamber 77 within which the coreremoval bit 34 is independently rotated by the mud motor at apredetermined rotational speed and rotational direction

For reamer bit stabilization, to minimize lateral movement of the reamerbit, the matrix material 56 and its PDC cutter supporting blades 58collectively define a downwardly facing centrally located opening orcore receiving receptacle or chamber 68. A bearing support sleeve member80 is seated within the bore 76 and is sealed to the body 52 of thereamer bit by a plurality of annular seal members 81 that are containedwith external seal recesses of the bearing support sleeve member 80. Thebearing support sleeve member 80 also serves as an internal wearresisting liner to protect the core removal bit 34 against excessivewear during drilling operations. A bearing set 82 having inner and outerbearing members is located between the bearing support sleeve member 80and a drive shaft 86 to which the core removal bit 34 has rotary drivingconnection, thus providing for rotary stabilization of the core removalbit during its rotation.

It should be noted that the mud motor 74 is supported within the tubularhousing 36 of the well drilling system 30 by means of a top mount sothat the mud motor and core removing bit as well as the bearing pack ofthe mud motor are supported by the upper end portion of the tubularhousing. As shown in FIGS. 2 and 9, a top-mount body 83 having adrilling fluid flow passage 84 therein is positioned within the tubularbody and has a splined connection 85 that permits linear adjustment ofthe top mount body within the housing section 46 and prevents rotationof the top mount body relative to the housing section. The flow passage84 is eccentrically located within the top mount body 83 in that it isdefined about the laterally offset center-line C/L². An externallythreaded retainer and adjustment member 87 is received by an internalthreaded section 88 of the tubular housing section 46 and definesspanner recesses 89 by which the retainer and adjustment member 87 isrotated by a spanner tool for adjusting the position of the top mountbody 83 within the tubular housing and securing the top mount bodyagainst upward movement within the tubular body. A flow divertingpassage 90 within the top mount body 83 communicates the drilling fluidflow from a high pressure chamber 96 into fluid flow passage 84 with anannulus or annular reamer bit supply chamber 91 between the tubularhousing 36 and the top mount body 83 to provide for drilling fluid flowwithin the flow passage 84 of the top mount body and the annulus 91. Thetop mount body 83 defines an externally threaded connector 92 at thelower end thereof which establishes threaded engagement within aninternally threaded connector 93 of a mud motor top sub 94. The top sub94 has threaded connection with the upper internally threaded connectorof a tubular housing 95 of the mud motor 74. Fluid flow through the flowpassage 84 and into a motor operation chamber 97 is controlled by areplaceable flow control nozzle 98 to provide for controlled operatingspeed and power of the mud motor 74.

The top mount mud motor and dual bit drilling system of FIG. 10 differsfrom that of FIG. 9 in that the top mount body 83 defines a flow passage126 that is in communication with the high pressure chamber 96 under thecontrol of a replaceable flow control nozzle 127 so that fluid pressurewithin the annulus 91 and the motor operation chamber 97 is controlledby the respective flow control nozzles 127 and 98 according to the fluidpressure design of the mud motor and the reamer bit.

Within the mud motor 74 is provided a stator member 99 which is oftubular form and is composed of rubber or a rubber like polymer materialand defines a generally helical internal profile 100. An elongate rotormember 101, also having an external geometry that is composed of rubberor a rubber like polymer material, defines a generally helical externalprofile 102 that cooperates with the internal profile 100 of the statormember 99 so that the flowing drilling fluid passes along the length ofthe stator and rotor members and causes rotation of the rotor member.The rotor member 101 is provided with a structural core that extendsalong its length and provides stability and structural integrity for therotor member. A mud motor positioning and stabilizing member 103 islocated in close fitting relation within the tubular housing 36 anddefines an opening 104 within which the mud motor housing 95 isreceived. As the rotor member 101 is rotated within the stator memberconsiderable vibration forces are developed. The mud motor positioningand stabilizing member 103 is composed of a resilient material andfunctions to minimize transfer of the rotor vibration forces to the mudmotor housing and to the tubular housing 36. The lower end of the rotormember 101 defines a non-circular drive member 105 that is engagedwithin a non-circular receptacle 106 of a rotor driven shaft member 107,which is preferably a flex shaft composed of flexible and durablematerial, such as beryllium copper, to minimize shock forces that aretransmitted by the rotor of the mud motor to the drive shaft and coreremoval bit of the drilling system.

As shown in FIG. 4, the rotor driven shaft 107 has a lower end definingcross-over ports 108 and a flow passage 109 and has threaded connectionat 110 with the upper end portion 111 of the tubular drive shaft 86 ofthe core removal bit 34. The drive shaft 86 defines a central flowpassage 112 that is in communication with the flow passage 109 andconducts drilling fluid flow to the core removal bit 34 for cooling thebit and for flushing away drill cuttings that occur at the cutting face70. A bearing pack, shown generally at 113 in FIG. 4 includes sets ofradial bearings 114 and thrust bearings 115. Drilling fluid beingdischarged from the stator and rotor during operation of the mud motorenters an annular flow passage 116, as shown at the lower portion ofFIG. 3 and flows downwardly for cooling and lubrication of the bearingpack and for cooling and flushing drill cuttings from the core removalbit 34. An annular fluid flow clearance or passage 117 exists throughthe bearing pack 113, thereby permitting drilling fluid flow through thebearing pack for cleaning and cooling the bearings and materiallyenhancing the service life of the core removal bit mud motor and itsbearing members. The drilling fluid is discharged from the clearance orflow passage 117 of the bearing pack into the chamber 77 within whichthe core removal bit 34 is located and then flows through the clearance75 between the exterior surface of the core removal bit 34 and thesurface 76 of the bit chamber within which the core removal bit is alsopositioned for core cutting rotation.

As the reamer bit 32 of FIG. 5 is rotated by the drill string and weightis applied a circular region of the subsurface formation is cut away,thereby leaving a formation core 72 that enters the downwardly facingopening 68. As drilling continues the upper end portion of the formationcore is contacted by the cutting face 70 of the core removal bit so thatcontinued penetration of the dual bit mechanism causes the core removalbit 34 to continuously cut away the formation core from top to bottom.This activity causes the formation core 72 to have a generallycylindrical external surface that is in close fitting relation with theinner surface segments 71 of the cutter supporting blade members of thereamer bit. A benefit of this close fitting relationship is that theformation core functions as a stabilization gauge to stabilizecontrolled rotation of the reamer bit and maintains controlled trackingof the course of the wellbore that is being drilled. The formation corethus prevents the reamer bit from wandering or being forced off courseduring the drilling process. To maintain the close fitting relationshipof the formation core and the inner surface segments 71, gauge protectormembers 118 are inset within the matrix material of the cutter supportblades and function to ensure against accelerated wear or erosion of thecylindrical surface of the formation core. Controlled tracking of thedual bit drilling system is also enhanced by the rapid drill bitpenetration that occurs due to the absence of any formation crushingactivity at the centermost region of the wellbore being drilled. Thedrive shaft 86 defines an externally threaded lower extremity 119 thatis received in threaded engagement within an internally threadedreceptacle 120 of the bit body 121 of the core removal bit 34.

When the reamer bit is rotated to the right by the drill string and thecore removal bit 34 is rotated to the left by its mud motor, as in FIGS.5, 6, 16 and 17, the threads of the mud motor components will be lefthand threads to ensure against unthreading of the mud motor componentsby the reactive torque that is developed as the core removal bit cutsaway the formation core. When both the reamer bit and the core removalbit are driven to the right, the thread connections throughout the mudmotor and drive shaft will be right hand threads since threaddisengagement will not occur. However, in this case the core removal bitshould be rotated at a greater rotational speed than the rotationalspeed of the reamer bit, so that the cutting speed of the core removalbit will be proper for the core cutting capability that is needed.

Drilling fluid distribution passages 122 are defined within the bit body121 of the core removal bit 34 and serve to conduct fluid flow from theflow passage 112 of the drive shaft 86 to the cutting face of the coreremoval bit. Replaceable flow control nozzles 123 are located at theoutlet openings of the drilling fluid distribution passages 122 andensure proper drilling fluid flow to the cutting face of the coreremoval bit. Drilling fluid within the annulus 91 is permitted to flowthrough fluid distribution passages 124 within the body 52 of the reamerbit and to exit between the cutter supporting blades 58 under thecontrol of replaceable flow control nozzles 125.

The tubular housing of the mud motor 74 is defined in part by a bearinghousing section 126 that encapsulates the bearings 114 and 115 anddefined an internal annular flange 127 that defines shoulders forbearing support and positioning. A drive shaft enlargement 128 alsodefines a bearing support and positioning shoulder for the thrustbearings 115. The lower portion of the tubular housing of the mud motor74 is defined by a housing sub 130 that has threaded connection with thebearing housing section 126 at 132. A downwardly facing generally planarannular surface 134 of the housing sub is seated for positioning andstability on a corresponding upwardly facing annular surface 135 that isdefined within the reamer bit body 52. The drive shaft 86 of the coreremoval bit 34 extends through a central passage 136 of the housing sub130 with sufficient annular clearance that drilling fluid flows throughthe clearance and through the bearing set 84 to the bit chamber 77.

With reference to FIGS. 11-21, there is disclosed a concentric dual bitwell drilling mechanism is disclosed wherein a reamer bit and a coreremoval bit rotate about a common longitudinal center-line C/L¹. Asshown in FIGS. 11-14, wherein like reference numerals identify likeparts, the dual bit drilling system 30 has a tubular housing 36 thatdefines a longitudinal center-line C/L¹ about which the center of theflow passage 22 is concentric. A connecting sub 38 of the housing 36 isalso concentric with the longitudinal center-line C/L¹ and the centersof the intermediate housing section 46 and the reamer bit body 52 arealso concentric with the longitudinal center-line C/L¹. Like componentsare identified by like reference numerals.

FIGS. 19 and 20, in addition to showing most of the features of FIG. 18,illustrate a top mount body 130 that is received within the tubularhousing section 46 of the housing 36 and has an internally splinedsection 131 similar to the splined section 85 of FIG. 18. The top mountbody 130 has external splines 132 that fit within the internal splinedsection 85 and thus permit linear movement of the top mount body withinthe tubular housing section 46 while ensuring that the top mount body isnot rotatable within the housing section. The top mount body is linearlyadjustable within the housing section 46 by means of an externallythreaded adjustment member 87 that is threaded within the housing by athread connection 88. This threaded adjustment permits the mud motormechanism, its drive shafts and the core removal bit to be adjustablewithin the tubular housing. The threaded adjustment member 87 is rotatedfor linear adjustment by the use of a tool such as a spanner device. Theentire mud motor mechanism, including the mud motor housing 95, itsbearing pack, drive shaft and the core removal bit are inserted into themud motor housing as a unit. The adjustment member 87 is then installedand adjusted to ensure against longitudinal movement of the mud motorwithin the housing 36 of the dual bit drilling system.

As shown in FIG. 19, the top mount body 130 defines a plurality of flowpassages, two of which are shown at 133 and 134, which permit the flowof drilling fluid from the high pressure chamber 96 into the annulus orannular drilling fluid supply chamber 91 that supplies the reamer bit.Replaceable flow control nozzles 135 and 136, which are threaded intothe inlets of the reamer bit flow passages, are seated within anupwardly facing recess 137 of the top mount body and control the flow ofdrilling fluid within the passages 133 and 134. These flow controlnozzles can be changed out as well conditions dictate. For control ofthe supply of drilling fluid to the mud motor and core removal bit anelongate support shaft 138 extends downwardly from the central portionof the top mount body 130 and defines a central flow passage 139 throughwhich drilling fluid flows from the high pressure chamber 96. Areplaceable flow control nozzle 140 is threaded into the externallythreaded lower end portion of the support shaft 138 and can be changedout as well conditions dictate. The mud motor top sub 94 is threadedonto the lower end portion of the support shaft 138 by a threadconnection 141.

During borehole drilling with the reamer bit 32, the core removal bit 34of FIGS. 5-8, being eccentrically located with respect to the center ofthe reamer bit, will have an orbital motion as well as being rotatedindependently of the rotary motion of the reamer bit. This orbitalmotion causes the PDC cutter members of the core removal bit to sweepacross the central region of the borehole, thereby continuously cuttingaway the small core that remains as the formation is cut away by thereamer bit. The core removal bit 34 is rotated by the core removal bitmud motor 74, which requires very little power for its operation,because of its small size in comparison with the size of the reamer bit.The core removal bit is driven at a significantly greater rotary speedwhich causes its PDC cutter members to move at an optimum speed relativeto the formation for efficiently cutting away the core region of theformation, without developing elevated heat. Moreover, the core removalbit is efficiently cooled during its operation by the volume of drillingfluid that is discharged at its cutting face from the fluid controlnozzles of the core removal bit and from the clearance between the coreremoval bit and the central opening of the reamer bit.

Referring now to FIGS. 11-14 a dual bit well drilling mechanism is showngenerally at 30 which differs from the dual bit well drilling mechanism30 of FIGS. 2-6 principally in the concentric arrangement of the coreremoval bit 34 with respect to the reamer bit 32. In this case, thecentral opening 68 of the reamer bit is concentric with respect to thecenter-line C/L¹ of the reamer bit and with virtually all of the tubularcomponents of the tubular housing and core removal bit mud motor. Thoughthe core removal bit is rotated by its mud motor 74 in the same manneras discussed above in connection with FIGS. 2-6, it will not haveoscillating motion during rotation of the reamer bit since its rotationis concentric with the reamer bit. To continuously cut away the centralcore that remains due to rotary cutting of the borehole by the reamerbit, the core removal bit will simply be rotated by the core removal bitmud motor 74 and will rely totally on the arrangement and cuttingcapability of the cutting face 70 thereof.

According to the bottom view of FIG. 15 the top mount duel bit welldrilling mechanism 30, the reamer bit 32 is shown by a directional arrowto have right hand formation cutting or drilling rotation and theconcentric core removal bit 34 to have right hand cutting or drillingrotation as well Like components of the dual bit mechanism are indicatedby like reference numerals. The cutting face 70 of the core removal bitmay have any suitable configuration and may incorporate a wide range ofsuitable formation cutting materials without departing from the spiritand scope of the present invention. The core removal bit is shown inFigure and other Figures of the Drawings to have arrays of PDC cutterelements that extend to its center, but it should be borne in mind thatthe cutting face 70 of the core removal bit may be defined by otherformation cutting materials and other drill bit designs. For example, ahard and durable material such as tungsten carbide that is fixed to ametal drill bit body and may have a coating of PDC material affixedthereto is effectively serviceable for use as the core removal bit.Typically, the tungsten carbide or any other suitable hard and durablematerial is applied as a hard-facing to a bit body that is composed of adurable metal such as steel. The hard-facing material typically definesformation cutting teeth for continuously cutting away the formation corefrom top to bottom as drilling operations continue.

The longitudinal section view of FIG. 16 shows a concentric dual bitmechanism having a reamer bit that is rotated to the right for drillingactivity and a core removal bit that is concentric within the reamer bitand is rotated to the left during drilling and a core removable bit thatis rotated to the left. FIG. 17 is a bottom view of the dual bitmechanism of FIG. 16. The longitudinal section views of FIGS. 18 and 19and the transverse section view of FIG. 20 also show the concentricversion of the dual bit well drilling system of the present inventionand differ only in the particular design of the top mount mechanism.

FIG. 21 is a longitudinal section view showing the concentric dual bitdrilling system of the present invention in its entirety, while FIG. 22shows the eccentric version of the dual bit drilling system of theinvention. The transverse section view of FIG. 23 is taken along line23-23 of FIG. 22 and shows the laterally offset center-line C/L² of theembodiment of FIG. 22.

In view of the foregoing it is evident that the present invention is onewell adapted to attain all of the objects and features hereinabove setforth, together with other objects and features which are inherent inthe apparatus disclosed herein.

As will be readily apparent to those skilled in the art, the presentinvention may easily be produced in other specific forms withoutdeparting from its spirit or essential characteristics. The presentembodiment is, therefore, to be considered as merely illustrative andnot restrictive, the scope of the invention being indicated by theclaims rather than the foregoing description, and all changes which comewithin the meaning and range of equivalence of the claims are thereforeintended to be embraced therein.

I claim:
 1. A top mount dual bit well drilling mechanism for drillingattachment to a tubular well drilling string extending from a drillingrig located at the Earth's surface, comprising: a tubular housing forconnection with a tubular well drilling string; a top mount body havingan upper end portion mounted in non-rotatable relation within saidtubular housing and having a connecting end; a drilling fluid energizedrotary motor being supported within said tubular housing by saidconnecting end of said top mount body; a reamer bit being connected withsaid tubular housing and having a plurality of spaced cutter retainingblades each having multiplicity of formation cutter elements mountedthereto and defining a downwardly facing core receiving receptacle, saidreamer bit being rotated by said tubular housing upon rotation of saidtubular housing by said tubular well drilling string, said reamer bitdefining a core removing bit chamber therein in communication with saiddownwardly facing core receiving receptacle; a core removing bit beingdisposed for rotation within said core removal bit chamber and having acutting face oriented for engaging and removing a formation core thatremains and enters said downwardly facing core receiving receptacle assaid formation cutter elements of said reamer bit cut a wellbore intothe formation; and a bit drive shaft being driven by said drilling fluidenergized rotary motor and being connected in rotary driving relationwith said core removing bit.
 2. The top mount dual bit well drillingmechanism of claim 1, comprising: said reamer bit having an axis ofrotation; said tubular housing of said drilling mechanism having alongitudinal center-line being concentric with said axis of rotation ofsaid reamer bit; said drilling fluid energized rotary motor having alongitudinal center-line; said top mount body supporting said drillingfluid energized rotary motor with said longitudinal center-line thereofbeing laterally offset from said longitudinal center-line of saidtubular housing of said drilling mechanism; and said core removing bitbeing rotatable about said longitudinal center-line of said drillingfluid energized rotary motor.
 3. The top mount dual bit well drillingmechanism of claim 1, comprising: said reamer bit having an axis ofrotation; said tubular housing of said well drilling mechanism having alongitudinal center-line being concentric with said axis of rotation ofsaid reamer bit; said drilling fluid energized rotary motor having alongitudinal center-line; said top mount body supporting said drillingfluid energized rotary motor with said longitudinal center-line thereofin concentric relation with said longitudinal center-line of saidtubular housing of said well drilling mechanism; and said core removingbit being rotatable about said longitudinal center-line of said drillingfluid energized rotary motor.
 4. The top mount dual bit well drillingmechanism of claim 1, comprising: said reamer bit defining a cuttingface; said core removing bit defining a cutting face being recessedwithin said reamer bit and located inwardly of said cutting face of saidreamer bit and permitting formation core stabilization of said reamerbit within said downwardly facing core receiving receptacle.
 5. The topmount dual bit well drilling mechanism of claim 1, comprising: saiddrilling fluid energized rotary motor having a tubular motor housing; astator member being located within said tubular motor housing; a rotormember being located within said stator member and being rotated bydrilling fluid flow between said stator and rotor members; and a bitdrive shaft being rotationally driven by said rotor member and havingdriving connection with said core removing bit.
 6. The top mount dualbit well drilling mechanism of claim 1, comprising: said reamer bithaving right hand rotation during well drilling; and said drilling fluidenergized rotary motor rotating said core removing bit to the leftduring well drilling.
 7. The top mount dual bit well drilling mechanismof claim 1, comprising: said reamer bit having right hand rotationduring well drilling; and said drilling fluid energized rotary motorrotating said core removing bit to the right during well drilling. 8.The top mount dual bit well drilling mechanism of claim 1, comprising:internal splines being defined within said tubular housing; externalsplines being defined by said top mount body and engaging said internalsplines and establishing a non-rotatable relationship of said top mountbody within said tubular housing; a retainer and adjustment member beingthreaded within said tubular housing and having retaining and adjustingengagement with said top mount body; said drilling fluid energizedrotary motor having a tubular motor housing being connected with andsupported by said top mount body and being seated within said reamer bitbody; and a bit drive shaft extending through said tubular housing andinto said core removing bit chamber and being in threaded drivingconnection with said core removing bit.
 9. The top mount dual bit welldrilling mechanism of claim 1, comprising: drilling fluid flow passagesbeing defined within said tubular housing and both internally andexternally of said drilling fluid energized rotary motor.
 10. The topmount dual bit well drilling mechanism of claim 1, comprising: adrilling fluid supply chamber being located within said tubular housingand externally of said top mount body and said drilling fluid energizedrotary motor; a substantially centrally located drilling fluid flowpassage extending longitudinally through said top mount body andproviding a supply of drilling fluid to said fluid energized rotarymotor; a flow diverting passage being defined in said top mount body andbeing in communication with said substantially centrally locateddrilling fluid flow passage and diverting a portion of the drillingfluid being supplied by the well drilling string into said drillingfluid supply chamber; and reamer bit supply passages being definedwithin said reamer bit and conducting flows of drilling fluid from saiddrilling fluid supply chamber to spaces between said cutter retainingblades.
 11. The top mount dual bit well drilling mechanism of claim 10,comprising: replaceable flow control nozzles being located withindesignated drilling fluid flow passages to control the volume ofdrilling fluid flow for operation of said drilling fluid energizedrotary motor, for cooling drilling components and to supply drillingfluid flow for efficient operation of said reamer bit and said coreremoving bit.
 12. A top mount dual bit well drilling mechanism fordrilling attachment to a tubular well drilling string extending from adrilling rig located at the Earth's surface, comprising: a tubularhousing having a mounting sub at the upper end thereof for rotary drivenconnection with a tubular well drilling string; a top mount bodydefining a drilling fluid flow passage therethrough and having an upperend portion mounted in non-rotatable relation within said tubularhousing and having a connecting end; a drilling fluid energized rotarymotor being supported within said tubular housing by said connecting endof said top mount body and defining a motor operation chamber incommunication with said drilling fluid flow passage of said top mountbody; a reamer bit being connected with said tubular housing and havinga plurality of spaced cutter retaining blades each having multiplicityof formation cutter elements mounted thereto and defining a reamer bitcutting face, said reamer bit defining a downwardly facing centrallylocated core receiving receptacle and being rotated by said tubularhousing upon rotation of said tubular housing by said tubular welldrilling string, said reamer bit defining a core removing bit chambertherein in communication with said downwardly facing core receivingreceptacle; a core removing bit being disposed for rotation within saidcore removal bit chamber and having a cutting face thereof locatedinwardly of said cutting face of said reamer bit and oriented forengaging and removing a formation core that remains and enters saiddownwardly facing core receiving receptacle as said formation cutterelements of said reamer bit cut a wellbore into the formation; and a bitdrive shaft being driven by said drilling fluid energized rotary motorand being connected in rotary driving relation with said core removingbit.
 13. The top mount dual bit well drilling mechanism of claim 12,comprising: said reamer bit having an axis of rotation; said tubularhousing of said drilling mechanism having a longitudinal center-linebeing concentric with said axis of rotation of said reamer bit; saiddrilling fluid energized rotary motor having a longitudinal center-line;said top mount body supporting said drilling fluid energized rotarymotor with said longitudinal center-line thereof being laterally offsetfrom said longitudinal center-line of said tubular housing of saiddrilling mechanism; and said core removing bit being rotatable aboutsaid longitudinal center-line of said drilling fluid energized rotarymotor.
 14. The top mount dual bit well drilling mechanism of claim 12,comprising: said reamer bit having an axis of rotation; said tubularhousing of said well drilling mechanism having a longitudinalcenter-line being concentric with said axis of rotation of said reamerbit; said drilling fluid energized rotary motor having a longitudinalcenter-line; said top mount body supporting said drilling fluidenergized rotary motor with said longitudinal center-line thereof inconcentric relation with said longitudinal center-line of said tubularhousing of said well drilling mechanism; and said core removing bitbeing rotatable about said longitudinal center-line of said drillingfluid energized rotary motor.
 15. The top mount dual bit well drillingmechanism of claim 12, comprising: said drilling fluid energized rotarymotor having a tubular motor housing; a stator member being locatedwithin said tubular motor housing; a rotor member being located withinsaid stator member and being rotated by drilling fluid flow between saidstator and rotor members; and a bit drive shaft being rotationallydriven by said rotor member and having driving connection with said coreremoving bit.
 16. The top mount dual bit well drilling mechanism ofclaim 12, comprising: internal splines being defined within said tubularhousing; external splines being defined by said top mount body andengaging said internal splines and establishing a non-rotatablerelationship of said top mount body within said tubular housing; aretainer and adjustment member being threaded within said tubularhousing and having retaining and adjusting engagement with said topmount body; said drilling fluid energized rotary motor having a tubularmotor housing being connected with and supported by said top mount bodyand being seated within said reamer bit body; and a bit drive shaftextending through said tubular motor housing and into said core removingbit chamber and being in threaded driving connection with said coreremoving bit.
 17. The top mount dual bit well drilling mechanism ofclaim 16, comprising: drilling fluid flow distribution passages beingdefined within said core removing bit; said drilling fluid energizedrotary motor having a stator within said tubular motor housing andhaving a rotor with said stator being rotated by drilling fluid flowbetween said stator and rotor; said rotor having a non-circular outputshaft drive member; a flex shaft having non-rotatable connection withsaid non-circular output shaft drive member and cushioning shock forcesof said rotor; a tubular bit drive shaft being connected in drivenrelation with said flex shaft and being connected in driving relationwith said core removing bit and having a drilling fluid flow passagetherein in communication with said drilling fluid flow distributionpassages of said core removing bit.